Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
  • C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
  • C09K8/504—Compositions based on water or polar solvents
  • C09K8/5045—Compositions based on water or polar solvents containing inorganic compounds
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
  • C09K8/504—Compositions based on water or polar solvents
  • C09K8/506—Compositions based on water or polar solvents containing organic compounds
  • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
  • C09K8/514—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
  • C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
  • C09K8/518—Foams
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
  • C09K8/592—Compositions used in combination with generated heat, e.g. by steam injection
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
  • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection

Definitions

• the present invention relates to a method for crude oil extraction, in which an aqueous flooding medium comprising water, a glucan, urea and optional surfactants is injected into the petroleum formation and the formation takes petroleum through at least one production well, wherein the formation has a temperature of at least 60 ° C. ,
• the formulation forms in-situ foams in the formation under the influence of formation temperature as well as gases which lead to the formation of an alkaline bank in the oil-bearing layer.
• natural oil deposits petroleum is present in cavities of porous reservoirs which are closed to the earth's surface by impermeable facings.
• the cavities may be very fine cavities, capillaries, pores, for example those having a diameter of only about 1 ⁇ m; however, the formation may also have areas of larger diameter pores and / or natural fractures or cracks.
• the most common method of secondary oil production is water flooding.
• water is injected into the oil-carrying layers through so-called injection bores. This artificially increases the reservoir pressure and forces the oil from the injection wells to the production wells.
• a water front emanating from the injection well should press the oil evenly over the entire petroleum formation to the production well.
• a petroleum formation has regions with different high flow resistance.
• areas with low resistance to flow for water such as natural or artificial fractures and cracks or very permeable areas in the reservoir rock.
• permeable areas can also be areas which have already been substantially deoiled by the water.
• gel-forming formulations can be used which are comparatively low in viscosity before injection and form highly viscous gels after injection into the formation.
• preferred flow paths are blocked for the flood water and the water is diverted into not yet de-oiled areas.
• Such measures are also known as "conformance control” or "water shut-off”.
• Aqueous solutions of cellulose ethers are relatively low viscosity at room temperature and do not form highly viscous gels at elevated temperatures
• measures to reduce the oil viscosity include, for example, C02 flooding and steam flooding the oil viscosity is reduced by the effect of the CO2 and in the Damp flood with the increase in temperature.
• the viscosity of the aqueous flooding media can be increased by the addition of suitable viscosity-increasing additives. These include, for example, the polymer flooding, in which one increases the viscosity of the aqueous phase by the addition of polymers or foam flooding.
• Glucosylglucans are branched homopolysaccharides of glucose units.
• the preparation of such glucosyl glucans and their use for crude oil production is disclosed, for example, in EP 271 907 A2, EP 504 673 A1, DE 40 12 238 A1 and WO 03/016545.
• Glucosylglucans have a high temperature stability and are therefore particularly suitable for oil reservoirs high reservoir temperatures.
• foam flooding techniques are disclosed in, for example, the following publications: US 5,074,358 and US 5,363,915 disclose tertiary petroleum production processes using foams.
• CO2, N2 or CH4 can be used as foaming gases.
• Foaming may be accomplished by either alternately injecting gas and foam forming formulations into the formation or by forming a foam and injecting the foam into the formation (see, e.g., US 5,363,915, column 6, line 3 et seq.).
• US Pat. No. 5,307,878 likewise discloses a process for tertiary mineral oil production in which foams are used. To stabilize the foam, a substantially non-crosslinked polymer is additionally used.
• a variety of polymers are mentioned as polymers, for example synthetic polymers such as polyvinyl alcohol, polyethylene oxide, polyvinylpyrrolidone, polyacrylamide, partially hydrolyzed polyacrylamide or natural polymers such as xanthan, scleroglucan, hydroxypropylcellulose or hydroxyethylcellulose.
• RU 2 190 091 C2 discloses a multi-stage process for tertiary mineral oil extraction, in which one injects first a polymer solution, then a foam-forming formulation and a gas and then again a polymer solution.
• the aqueous foam-forming formulation comprises water, alkali, a surfactant and a water-soluble polymer having M n 300 to 30 000 g / mol.
• the polymer may be, for example, xanthan, guar gum, polyacrylamide or partially hydrolyzed polyacrylamide.
• the gases with the foam-forming formulation must mix with each other after injection into the deposit underground to form a foam.
• a uniform and complete mixing is generally not achievable underground. Rather, as a rule, a considerable part of the foam-forming formulations does not come into contact with the gases, so that no uniform foam bank is formed in the formation.
• the gases escape mainly to the higher areas of the deposit and the liquid to the lower areas.
• the technique of forming the foam on the surface is complicated, requires additional equipment, and does not guarantee that the foam will reach areas of the deposit farther away from the injector.
• RU 2 361 074 C2 discloses a process in which an aqueous solution of urea, ammonium nitrate, ammonium thiocyanate and surfactants and, alternately with it, steam is compressed into a crude oil deposit.
• the urea hydrolyzes and CO2 and ammonia form in the reservoir, causing an increase in de-oiling.
• foaming is often insufficient.
• the injected mixture of water and urea after injection, may mix with reservoir water present in the reservoir and thereby be diluted. As a result, the foaming is difficult and completely prevented by excessive dilution.
• the object of the invention was to provide an improved method for the production of oil by means of
• a process for extracting petroleum from a subterranean oil deposit into which at least one production well and at least one injection well have been connected, each associated with the deposit, the process comprising at least one process step (B) of passing petroleum Injection of an aqueous, water-soluble, thickening polymers comprehensive flood medium through the injection well and extraction of petroleum through the production well, the temperature during the process step (B) at least in a portion of the petroleum formation between the injection and the production well at least 60 ° C is and wherein the aqueous flooding medium next to water at least
• glucan with a beta-1, 3-glycosidically linked main chain and beta-1, 6- glycosidically attached side groups, wherein the glucan has a weight average molecular weight M w of 1, 5 * 10 6 25 * 10 6 g / mol, and urea comprises.
• FIG. 4 Schematic representation of crude oil production by means of the method according to the invention
• FIG. 5 Schematic representation of crude oil production by means of the method according to the invention after the implementation of measures for Conformance Control.
• At least one production well and at least one injection well are sunk into the crude oil deposit.
• a deposit is provided with multiple injection wells and multiple production wells.
• flooding media such as aqueous flood media or water vapor can be injected into the deposit.
• the oil flows in the direction of the production well and is conveyed through the production well.
• the term "petroleum” in this context not only means pure phase oil, but the term also includes the usual crude oil reservoir water emulsions.
• the petroleum may in principle be any kind of crude oil
• the oil in the reservoir may have a viscosity of at least 30 mPa * s (measured at the natural reservoir temperature)
• typical cations include Na + , K + , Mg 2+ or Ca 2+
• typical anions include chloride, bromide, bicarbonate, sulfate or borate
• the salinity of the reservoir water may be 20,000 ppm to 350,000 ppm (weight percentages of the sum of all components of the reservoir water), for example 100,000 ppm to 250,000 ppm.
• the amount of alkaline earth metal ions, in particular of Mg 2+ and Ca 2+ ions can be 1000 to 53 000 ppm.
• reservoir water contains one or more alkali metal ions, in particular Na + ions.
• alkaline earth metal ions may also be present, the weight ratio of alkali metal ions / alkaline earth metal ions generally being> 2, preferably> 3.
• at least one or more halide ions, in particular at least chloride ions are generally present.
• the amount of Ch is at least 50% by weight, preferably at least 80% by weight, with respect to the sum of all anions.
• the process according to the invention comprises at least one process step (B) in which an aqueous flooding medium is employed which comprises at least water, a glucan (G) having a ⁇ -1,3-glycosidically linked main chain and ⁇ -1,6-glycosidically linked side groups and urea.
• the urea decomposes after injection into the deposit under the influence of the deposit temperature and forms CO2 and NH3.
• the process may optionally comprise at least one additional process step (A), which is carried out prior to process step (B), and which also injects flood media into the reservoir.
• the flooding medium is preferably either an aqueous flooding medium (process step (A1)) or steam (process step (A2)).
• the process may optionally comprise at least one additional process step (C), which is carried out after a process step (B) and in which flooding media are likewise injected into the reservoir.
• the flooding medium is preferably either an aqueous flooding medium (process step (C1)) or steam (process step (C2)).
• process step (B) and the optional process steps (A) and (C) can be carried out several times. For example, they can be executed cyclically several times in succession.
• the method may also optionally include further method steps.
• This may be a further process step (D).
• step (D) a formulation of a thermogel, which is thickened by means of a glucan (G), is injected, ie a formulation which after injection can form highly viscous gels under the influence of the formation temperature.
• G glucan
• permeable regions of the formation can be blocked so that subsequently injected aqueous flooding media must flow over new flood paths. This allows more oil to be mobilized.
• the temperature during process step (B) at least in a partial region of the petroleum formation between the injection and production well at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C and for example at least 90 ° C. It should not exceed 150 ° C, preferably 135 ° C and more preferably 120 ° C. It may be 60 ° C to 150 ° C, in particular 70 ° C to 140 ° C, preferably 75 ° C to 135 ° C and particularly preferably 80 ° C to 120 ° C.
• the term "area between the injection and production well” here means that part of the subterranean formation which is detected by the flooding process in the course of process step (B), ie those areas by the flood media injected and / or the oil mobilized thereby during the flooding process Naturally, this is not the shortest route from the injection to the production well, but rather the flow paths are oriented according to the geological conditions in the formation and may therefore be longer
• the temperature in the entire area of the injection and production well may preferably have the values given above
• the temperature in the entire area between the injection and production wells should have the abovementioned maximum temperatures of 150.degree , b preferably 135 ° C, and more preferably 120 ° C.
• the temperatures mentioned may be the natural reservoir temperature.
• the natural reservoir temperature can be changed by process step (B) preceding flooding operations. If, for example, the deposit is flooded with cold water for a long time before carrying out process step (B), the temperature of the deposit is lowered starting from the injection well, with the temperature approaching the natural reservoir temperature with increasing distance from the injection well. On the other hand, if the deposit is flooded with hot steam for a long time before carrying out process step (B), the temperature of the deposit is increased starting from the injection well.
• the temperature distribution in the formation can be determined before carrying out process step (B).
• Methods for determining the temperature distribution of a crude oil deposit are known in principle to the person skilled in the art.
• the temperature distribution is usually made from temperature measurements at specific points of the formation in combination with simulation calculations, wherein the simulation calculations take into account, inter alia, amounts of heat introduced into the formation and the quantities of heat removed from the formation.
• glucans is understood by the person skilled in the art to mean homopolysaccharides which are composed exclusively of glucose units
• a particular class of glucans is used, namely glucans comprising a main chain of ⁇ -1,3-glycosidically linked glucose units
• the side groups consist of a single ⁇ -1, 6-glycosidically linked glucose unit, which, statistically speaking, every third unit of the main chain is connected to another glucose unit ⁇ -1, 6 -glykosisch is linked.
• glucans are secreted by certain fungal strains, and corresponding fungal strains are known to those skilled in the art. Examples include Schizophyllum commune, Sclerotium rolfsii, Sclerotium glucanicum, Monilinia fructigena, Lentinula edodes or Botrytis cinera. Suitable fungal strains are mentioned, for example, in EP 271 907 A2 and EP 504 673 A1, each claim 1.
• the fungi strains employed are Schizophyllum commune or Sclerotium rolfsii, and more preferably Schizophyllum commune, which secretes a glucan, in which every third unit of the main chain is attached to a main chain of ⁇ -1,3-glycosidically linked glucose units is linked to another glucose unit ⁇ -1, 6-glycosidically; ie, preferably, the glucan is the so-called schizophyllan.
• the glucans used for the invention have a weight-average molecular weight M w of about 1.5 to about 25 * 10 6 g / mol, in particular 2 to about 15 * 10 6 g / mol.
• glucans The preparation of such glucans is known in principle.
• the fungi are fermented in a suitable aqueous nutrient medium.
• the fungi secrete the above-mentioned class of glucans into the aqueous fermentation broth during the fermentation, and an aqueous polymer solution can be separated from the aqueous fermentation broth.
• an aqueous solution containing glucans is separated, leaving an aqueous fermentation broth in which the biomass has a higher concentration than before.
• the separation can be carried out in particular by means of single or multi-stage filtration or by centrifugation. Of course, several separation steps can be combined.
• the MPFR value of the filtrates should be as low as possible, and in particular 1, 001 to 3, preferably 1, 01 to 2.0.
• the filtration can preferably be carried out by means of cross-flow filtration, in particular cross-flow microfiltration.
• the method of cross-flow microfiltration is known in principle to a person skilled in the art and is described, for example, in “Melin, Rautenbach, Membran compiler, Springer-Verlag, 3rd edition, 2007, page 309 to page 36.”
• the term "microfiltration” is understood by the person skilled in the art to mean the separation of particles of a size between about 0.1 ⁇ to about 10 ⁇ .
• a process for producing glucans using cross-flow filtration is disclosed in WO 201 1/082973 A2. From the resulting filtrate can be separated the glucans.
• the glucans are not separated, but the aqueous glucan solution obtained is used directly for the preparation of the flood media for process step (B).
• the concentration of the glucan solutions obtained can be, for example, 5 to 25 g / l.
• Solutions of the glucans (G) used according to the invention have a high viscosity even in low concentrations, the viscosity in the temperature range from room temperature to about 140 ° C. largely independent of the temperature and largely independent of the temperature Salinity in the formation water is (see Fig. 2 and Fig. 3). Details on this are shown in the game section.
• an aqueous flooding medium which, in addition to water, comprises at least one glucan (G) and also urea.
• water-miscible organic solvents may optionally be used in small amounts, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preferably, only water is used as the solvent.
• the water may be fresh water or water containing salts.
• it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner.
• the concentration of glucan (G) depends on the desired viscosity of the flooding medium for process step (B).
• the viscosity of glucan solutions at various concentrations is shown in Figure 1, the dependence of the viscosity on the temperature in Figures 2 and 3.
• the viscosity of the aqueous flooding medium for process step (B) depends mainly on the type and concentration of the glucan (G) used. It should be adapted to the viscosity of the oil phase and can be more accurately determined using the ratio (R) between flood medium mobility (M w ) and oil mobility (MO):
• ⁇ refers here to the aqueous flooding medium under conditions of use in the formation. Ideally set to values ⁇ 1.
• R the optimal ratio between the water mobility (M w ) and the oil mobility (M ⁇ ) is mostly unavailable, especially for highly viscous oils, because one has to develop unrealistically high injection pressures. One can therefore also work with values R> 1. But even a slight increase in the viscosity of the water phase by means of glucan tends to improve the oil yield.
• the concentration of glucan (G) is 0.1 g / l to 20 g / l, preferably 0.1 to 5 g / l and particularly preferably 0.1 to 2 g / l.
• the aqueous formulation furthermore comprises urea.
• Urea H2N-CO-NH2 hydrolyzes in water at elevated temperature to CO2 and ammonia.
• the hydrolysis reaction is naturally temperature-dependent and proceeds the faster the higher the temperature. If the urea hydrolyzes under the influence of the deposit temperature in the formation, the gases naturally form directly in the formation and thus foams can form in the formation.
• the amount of urea in the flooding medium for carrying out process step (B) is generally 15 to 350 g / l of the formulation, in particular 15 g / l to 300 g / l, preferably 30 g / l to 250 g / l and particularly preferred 50 g / l to 250 g / l.
• the formulation may further comprise at least one ammonium salt.
• suitable ammonium salts include, in particular, ammonium nitrate and ammonium chloride.
• the amount of ammonium salts in the flooding medium for carrying out process step (B) is generally 20 to 300 g / l of the formulation, in particular 20 g / l to 250 g / l, preferably 30 g / l to 250 g / l and particularly preferred 50 g / l to 250 g / l.
• the formulation may further comprise at least one surfactant.
• Foaming surfactants are particularly suitable for this purpose. Foaming surfactants have a certain film forming ability and thus promote the formation of foams. Examples of foam-forming surfactants are known in principle to the person skilled in the art. Examples include anionic, cationic or nonionic surfactants, for example sulfates or sulfonates such as alkylbenzenesulfonates, alkoxylated alkylphenols such as alkoxylated nonylphenols.
• the amount of surfactants in the flooding medium for carrying out process step (B) is generally 0.1 to 5 g / l of the formulation, in particular 0.5 g / l to 5 g / l, preferably 1 g / l to 5 g / l and more preferably 2 g / L to 5 g / L.
• formulation for carrying out process step (B) may optionally contain further components, such as, for example, biocides or clay stabilizers.
• urea and solid glucan (G) as well as optionally further constituents in water can be dissolved.
• aqueous glucan solution obtained from the preparation.
• the solution can be mixed with the other components in the desired ratio and diluted to the desired concentration.
• Man can also pre-dissolved the other components, so for example, use an aqueous solution of urea and mix with an aqueous glucan (G) - solution.
• said formulation is injected through the at least one injection well into the formation.
• the flood medium used for process step (B) is injected into the formation at a temperature of less than 60 ° C., preferably less than 35 ° C., particularly preferably less than 25 ° C. and, for example, about room temperature.
• the hydrolysis begins with appreciable speed when the urea-containing formulation in the formation has warmed to temperatures of at least 60 ° C. Naturally, the rate of hydrolysis increases with increasing temperature. Preferred temperatures for at least a portion of the petroleum formation between the injection and production wells have already been mentioned above.
• the formed gases NH3 and CO2 have different effects in the formation. Part of the formed NH3 dissolves in the water forming an alkaline zone and part of the formed CO2 dissolves in the oil and increases its mobility.
• the remaining amounts of gas form with the components of the formulation for process step (B), ie at least the glucan (G) and optionally the surfactants foams.
• the process according to the invention with process step (B) has the advantage that the combination of the temperature- and salt-stable glucan (G) with urea gives positive synergistic effects in the case of the de-oiling.
• the degree of deoiling is - compared to the water flooding - improved not only in a manner known in principle by the use of thickening acting polymers, but by combining with urea additional effects are achieved.
• Hydrolysis of urea in the petroleum formation creates moving zones (banks) enriched with ammonia and CO2.
• the distribution coefficient of CO2 in the system oil-water is 35 - 100 ° C and 100 to 400 bar at about 4 to 10.
• the C0 2 accumulates significantly in the oil, and the CO2 of the viscosity of the oil in principle known Way reduced.
• the formation of foams is supported by the glucan, because the escape of gases into less deep-lying zones of the oil reservoir is significantly impeded by the viscous polymer solution compared to the use of non-thickened water as a flood.
• the foam phases have a higher viscosity than the unfoamed water phase, which results in a more uniform flooding.
• the gas production in the carrier also increases the local formation pressure and thus also supports the oil displacement. Since the unfoamed aqueous urea-glucan solution has a lower viscosity than the foam, the aqueous flooding medium first flows through the highly permeable zones of the formation after injection. After foaming, the flow through the highly permeable zones is made much more difficult.
• the process may optionally comprise at least one additional process step (A), which is carried out prior to process step (B), and which also injects flood media through the injection well (s) into the reservoir and removes petroleum through at least one production well.
• the flooding medium is an aqueous flooding medium (process step (A1)).
• This may be fresh water or saline water.
• it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner.
• water-miscible organic solvents may optionally be used, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water.
• the injected aqueous flood medium may have a low temperature, for example a temperature in the range of 10 ° C to 35 ° C or about room temperature.
• Such temperatures usually result automatically, for example, it is the temperature of the seawater used for flooding. But it can also be a warmed aqueous flooding medium. For example, it can be water with a temperature of at least 80 ° C. It can also be overheated water, ie liquid water with a temperature of more than 100 ° C. Naturally, the pressure is higher than 1 bar; Under conditions of injecting into a petroleum formation, a pressure of 1 bar is generally clearly exceeded.
• the aqueous flooding medium for process step (A1) may of course also comprise additional components in addition to water or salt water.
• additional components may be thickening components, in particular thickening polymers.
• This may preferably be a glucan (G).
• the viscosity of a glucan-containing aqueous flooding medium should in this case preferably be such that the viscosity of a flooding medium injected in a process step (A1) is lower than the viscosity of the aqueous flooding medium injected in subsequent process step (B).
• the injected flooding medium may be steam (process step (A2)).
• Water vapor may have a temperature of more than 300 ° C when injected into the oil reservoir. Additional process step (C)
• the process may optionally comprise at least one additional process step (C) which is carried out after a process step (B) and which also injects flood media through the injection well (s) into the reservoir and removes petroleum through at least one production well.
• the flooding medium is an aqueous flooding medium (process step (C1)).
• This may be fresh water or saline water.
• it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner.
• water-miscible organic solvents may optionally be used, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preferably, only water is used as the solvent.
• the injected aqueous flood medium may have a low temperature, for example a temperature in the range of 10 ° C to 35 ° C or about room temperature. But it can also be a warmed aqueous flooding medium. For example, it may be
• the aqueous flooding medium for process step (C1) may of course also comprise additional components in addition to water or salt water.
• additional components may be thickening components, in particular thickening polymers. This may preferably be a glucan (G).
• the viscosity of a glucan-containing aqueous flooding medium should in this case preferably be such that the viscosity of a flooding medium injected in a process step (C1) is higher than the viscosity of the injected in step (B) aqueous flooding medium.
• the injected flooding medium may be water vapor (process step (C2)).
• Water vapor may have a temperature of more than 300 ° C when injected into the oil reservoir.
• Process steps (A), (B) and (C) may be combined with each other.
• the combination may, for example, be one of the following flow diagrams 1 to 4.
• Aqueous medium Aqueous medium
• sequence of method steps (A) -> (B) -> (C) can also be repeated cyclically one after the other.
• flooding is first carried out with an aqueous flooding medium as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea and finally flooded again with an aqueous flooding medium.
• B the flooding medium comprising glucan and urea
• the natural reservoir temperature should be at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C, and for example at least 90 ° C. It may be 60 ° C to 150 ° C, in particular 70 ° C to 140 ° C, preferably 75 ° C to 135 ° C and particularly preferably 80 ° C to 120 ° C.
• step (A2) cold flood water, so for example flood water is used with a temperature in the range of 10 ° C to 35 ° C, namely, the temperature of the crude oil deposit in the environment injection point gradually decreases over time. Flooding a reservoir with water can take months or even years. Naturally, the cooling at the injection site itself is greatest, and with increasing distance from the injector the temperature approaches the natural reservoir temperature again. A sufficient natural reservoir temperature ensures that the actual reservoir temperature, as required to carry out the process, is at least 60 ° C, at least in a portion of the petroleum formation between the injection and production wells.
• aqueous flooding medium of the injection for example, to temperatures of at least 80 ° C.
• the amount of glucan (G) should in this case be such that the viscosity of the aqueous flooding medium injected in process step (C1) is greater than the viscosity of the aqueous flooding medium injected in process step (B).
• Such a measure counteracts the effect of "fingering.”
• Fingering means that a lower viscosity flooding phase does not form a uniform flow front to a higher viscous flooding phase, but that the flow front is uneven. This is mainly due to the fact that the lower-viscosity flood phase flows faster through permeable zones, while less permeable zones flow through more slowly. “Fingering” can largely be avoided if the subsequent flooding phase is more viscous.
• flooding is carried out with an aqueous flooding medium which are thickened, preferably in each case with the aid of a glucan (G), the viscosity of the flooding phase used being in the order (A1 ) -> (B) -> (C1) increases.
• flood Scheme 2 In Flood Scheme 2, flooding is first carried out with steam as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea, and finally flooded with steam again.
• the natural reservoir temperature may also be less than 60 ° C.
• the water vapor used for injecting typically has temperatures of up to 300 ° C, the deposit heats up from the injection well with increasing duration of steam injection, so that at least in a portion of the petroleum formation between the injection and the production well a temperature of at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C and for example at least 90 ° C is achieved. However, it should reach 150 ° C., preferably 135 ° C. and more preferably 120 ° C. If these values are exceeded, before starting process step (B), an intermediate flooding with cold water, for example, water at temperatures of 10 ° C to 35 ° C take place.
• process step (B) is carried out.
• the duration of process step (B) may be determined by the skilled person depending on the desired results, but at the latest when the temperature in the entire region of the petroleum formation between the injection and the production well has fallen to temperatures of less than 60 ° C, process step (B ) stopped. It is advisable to stop process step (B) even when the temperature falls below 70.degree. C., particularly when the temperature falls below 80.degree.
• process step (C2) The process is then continued with the injection of steam (process step (C2)).
• process step (C2) In order to protect the flood phase (B), it may also be advisable to carry out an intermediate flooding with cold water before injecting the steam.
• the intermediate tide may also be thickened, preferably with the help of a glucan (G). If thickening is used, the viscosity of the intermediate flood should be at least as high as that of the flooding phase used for process step (B).
• flood Scheme 3 initially floats with water vapor as described above, then flooding with the flocculant (B) comprising glucan and urea, and then flooding is continued with an aqueous flooding medium.
• the temperature of the natural deposit can also be lower than 60 ° C in flood scheme 3, as in flood scheme 2, because the deposit warms up under the influence of water vapor.
• process step (C1) is carried out.
• flood Scheme 4 is first flooded with an aqueous flooding medium as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea, and finally flooded with steam.
• the natural reservoir temperature must be at least 60 ° C. Preferred temperature ranges have already been mentioned in flow diagram 1. It may also be useful in flood scheme 4 to flood after process step (B) with cold water-if necessary, thickened water between.
• Additional Process Step (D) By means of the additional process step (D), the process according to the invention can be combined with measures for "Conformance Control".
• injected aqueous flooding media or else steam preferably flow through the particularly permeable regions of the formation, which are thereby preferably de-oiled, while less permeable regions are flowed through with little or no flow.
• un mobilized oil will remain in the less permeable areas.
• Figure 4 An injection well (1) and two production wells (2, 2 ') were drilled into an oil reservoir.
• the aqueous flooding medium for process step (B) is injected, flows in the direction of the production wells (2, 2 ') and thereby presses the petroleum in front of him.
• the so-called displacement wave ie the boundary between the aqueous phase and the petroleum phase
• the preferred flood paths (3) for the aqueous phase or the mobilized petroleum are shown hatched. These are not straightforward but follow the permeable zones of the formation. Outside the shaded area unimmobilized oil remains. Also marked is the 60 ° C isotherm (4). Within the marked zone it is colder, outside the zone it is warmer. In the areas with a temperature above 60 ° C, the urea begins to hydrolyze and, accordingly, the foaming begins.
• a formulation of a thermogel, which is thickened by means of a glucan (G), is injected, ie a formulation which after injection can form highly viscous gels under the influence of the formation temperature.
• the formulation comprises at least one glucan (G), urea and at least one water-soluble aluminum (III) salt and / or a partially hydrolyzed aluminum (III) salt.
• the water-soluble aluminum (III) salts may be, for example, aluminum chloride, aluminum bromide, aluminum nitrate, aluminum sulfate, aluminum acetate or aluminum acetylacetonate. But it can also be already partially hydrolyzed aluminum (III) salts, such as aluminum hydroxychloride.
• the pH of the formulation should be ⁇ 5, preferably ⁇ 4.5 and more preferably ⁇ 4.
• Aluminum (III) salts are acidic, so that this pH is usually set alone if Al (III) is sufficient. If necessary, ewtas could be acidified. It is preferably aluminum (III) chloride and / or aluminum (III) nitrate.
• thermogels The active principle of such thermogels is that the said aluminum (III) salts form acidic solutions, but form sparingly soluble gels in the alkaline range.
• the change in pH is triggered by the hydrolysis of urea at elevated temperatures, in which, as already described, ammonia forms.
• the thickening of the aluminum urea solution with the glucan has the effect that due to the increased viscosity, the injected formulation does not mix so easily with the reservoir water and previously injected flooding phase (B) (suppressing or at least reducing fingering). If thinning is too high, it would not be possible to form a highly viscous gel.Through thickening, the flood with the thermogel can run through longer stretches of the formation without being diluted too much thus blocking the formation at these locations
• the method may optionally include further method steps.
• this includes the already mentioned intermediate flooding with water between the process steps (A) and (B) and / or (B) and (C).
• the process can also be combined with surfactant floods.
• surfactant flooding an aqueous formulation of surfactants is injected into the formation, which surfactants reduce the water-oil interfacial tension after injection. Suitable surfactants for use in oil deposits are known in the art and are also commercially available.
• Surfactant flooding can advantageously be carried out before carrying out process step (B).
• a possible sequence of procedural steps would be, for example, process step (A1) -> surfactant flooding -> process step (B)> optional process step (C).
• Glucan (G) having a ⁇ -1,3-glycosidically linked main chain and ⁇ -1,6-glycosidically linked side groups (according to the invention)
• the glucan (G) was prepared by means of in WO 201 1/082973 A2, Inventive Example 1, pages 15 to 16 in the described apparatus. The concentrate obtained was diluted to the particular desired temperature for the experiments. Comparative Polymer 1:
• biopolymer xanthan (CAS 1 1 138-66-2) biopolymer, prepared by fermentation with the bacterium Xanthamonas campestris) having a weight-average molecular weight M w of about 2 million g / mol.
• Comparative Polymer 3 Commercially available biopolymer Diutane (biopolymer prepared by fermentation with Sphingomonas sp.)
• the glucan according to the invention and the comparison polymers were used to carry out the viscosity measurements described below. Execution of the viscosity measurements:
• Measuring instrument shear stress controlled.it physica MCR301 rotational viscometer
• the complete measuring system including the syringe used to draw the sample and place it in the rheometer, was purged with nitrogen. During the measurement, the measuring cell was exposed to 8 bar of nitrogen.
• Figure 1 shows that glucan P1 achieves the best viscosity efficiency in reservoir water, i. the samples give the highest viscosity at a given concentration.
• Test Series 2 There was the viscosity of aqueous solutions of the glucan (G) No P1 and the comparative polymers V1, V2 and V3 in high-purity water in a concentration of 3 g / l at a shear rate of 100 sec _1 in the temperature range of 25 ° C. measured up to 170 ° C.
• the solution of gluacan (G) No. P1 was diluted accordingly, and the polymers V1, V2 and V3 were dissolved in the corresponding concentration in water.
• the samples were injected at room temperature into the measuring cell and the heating rate was 1 ° C / min. The results are shown in Figure 2.
• the experiments show the advantages of the glucan (G) No. P1 used according to the invention in comparison to the comparison polymers V1, V2 and V3 at high temperature and high salt concentration.
• the viscosity of glucan (G) No. P1 remains constant in saline water as well as in ultrapure water at temperatures of 25 to 140 ° C and only then slowly begins to decrease.
• both the synthetic polymer V1 (copolymer of acrylamide and 2-acrylamido-2-methylpropane-sulfonic acid) and the biopolymer V3 show a similar behavior, while the biopolymer V2 is significantly worse.
• all comparative polymers V1, V2 and V3 are worse than the glucan P1 at higher temperatures. Gas formation by decomposition of urea
• Figure shows the formation of gas bubbles of CO2 of an aqueous solution of about 1, 5 g / l glucan (G), 20 wt.% Urea and 3 wt. % HCl when thermostating the solutions at 90 ° C.
• the figure shows gas formation after 1, 2 and 3 h.

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